Methods for injecting a consolidation fluid into a wellbore at a subterranian location

Abstract

Disclosed are apparatuses and methods for stabilizing portions of a subterranean formation and controlling the production of water from those subterranean formations. In one aspect, a method of treating a plurality of discrete portions of a subterranean formation penetrated by a wellbore, the method comprising the steps of: (a) moving a treatment tool through the wellbore on work tubing to a desired subterranean location, wherein the treatment tool comprises: (i) a fluidic oscillator; and (ii) a lower packer positioned below the fluidic oscillator; (b) expanding the cross-section of the lower packer to engage the wellbore, thereby isolating a portion of the wellbore from another portion below the lower packer; (c) injecting a consolidation fluid through the tubing and through the fluidic oscillator into the isolated portion of the wellbore; (d) reducing the cross-section of the lower packer, thereby disengaging the tool from the wellbore.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

None

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

None

REFERENCE TO MICROFICHE APPENDIX

Not applicable

TECHNICAL FIELD

The present inventions relate to methods for controlling the migration of unconsolidated particulates in a portion of a subterranean formation, and more particularly, to the using pressure pulses to enhance the effectiveness of placement of a consolidation fluid in a portion of a subterranean formation.

BACKGROUND

Hydrocarbon wells are often located in unconsolidated portions of a subterranean formation, that is, portions of a subterranean formation that contain particulate matter capable of migrating with produced fluids out of the formation and into a well bore. The presence of particulate matter, such as sand, in produced fluids may be disadvantageous and undesirable in that such particulates may abrade pumping equipment and other producing equipment and may reduce the fluid production capabilities of the producing portions of the subterranean formation. Unconsolidated portions of subterranean formations include those which contain loose particulates that are readily entrained by produced fluids and those wherein the particulates are bonded together with insufficient bond strength to withstand the forces produced by the production of fluids through the zones.

One conventional method used to control formation particulates in unconsolidated formations involves consolidating a portion of a subterranean formation into a hard, permeable mass by applying a curable resin composition to the portion of the subterranean formation. In one example of such a technique, an operator pre-flushes the formation, applies a resin composition, and then applies an after-flush fluid to remove excess resin from the pore spaces of the zones. Such resin consolidation methods are widely used but may be limited by the ability to place the resin through enough of the unconsolidated portion of the formation to adequately control the particulates. The compositions are often unable to achieve significant penetration or uniform penetration into the portion of the subterranean formation. Conditions such as variable formation permeability; formation damage in the near-well bore area; debris along the well bore, a perforation tunnel, or a fracture face; and, compaction zones along the well bore, a perforation tunnel, or a fracture face may make uniform placement of resin compositions extremely difficult to achieve. The problems are particularly severe when used to treat long intervals of unconsolidated regions.

The present inventions seek to use the increased flow benefits of pressure pulsing to increase the ability of a consolidation fluid to penetrate a portion of a subterranean formation.

SUMMARY OF THE INVENTIONS

The present inventions provide apparatuses and methods for treating a wellbore. According to one aspect of the inventions, a method of treating a portion of a subterranean formation penetrated by a wellbore is provided. The method comprises the steps of:

(a) moving a treatment tool through the wellbore on work tubing to a desired subterranean location, wherein the treatment tool comprises:

• • (i) a fluidic oscillator; and
  • (ii) a lower packer positioned below the fluidic oscillator;

(b) expanding the cross-section of the lower packer to engage the wellbore, thereby isolating a portion of the wellbore from another portion below the lower packer;

(c) injecting a consolidation fluid through the tubing and through the fluidic oscillator into the isolated portion of the wellbore;

(d) reducing the cross-section of the lower packer, thereby disengaging the tool from the wellbore.

These and further aspects and advantages of the invention will become apparent to persons skilled in the art from the following detailed description of presently most-preferred embodiments of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete understanding of the present inventions and the advantages thereof may be acquired by referring to the following description taken in conjunction with the accompanying drawings in which:

FIGS. 1D-1D illustrate an example of a treatment tool positioned on the end of a pipe string in a wellbore, wherein the treatment tool includes a fluidic oscillator between two inflatable packers of a straddle packer, where: in FIG. 1A, the tool is shown in a run-in position with the inflatable straddle packer in a deflated condition adjacent a zone of lower wellbore perforations; in FIG. 1B, the tool is shown in a set position with the inflatable packers in an inflated position to isolate the lower zone of wellbore perforations and fluid treatment of the lower zone; in FIG. 1C, the tool is shown in a run position with the inflatable packers again deflated allowing the tool to be moved in the wellbore; and in FIG. 1D, the tool is shown in an set position again with the inflatable packers in an inflated position to isolate the upper zone of wellbore perforations for fluid treatment of the upper zone.

FIG. 2 illustrates an example fluidic oscillator with a portion of its housing removed to expose an insert.

FIG. 3 illustrates an insert for an example fluidic oscillator;

FIG. 4 illustrates a pattern view of an insert for an example fluidic oscillator;

FIG. 5 illustrates a side view of an insert for an example fluidic oscillator;

FIG. 6 illustrates an insert for an example fluidic oscillator;

FIG. 7 illustrates a side view of an insert for an example fluidic oscillator;

FIG. 8 illustrates an insert for an example fluidic oscillator;

FIG. 9 illustrates a housing for an example fluidic oscillator;

FIG. 10 illustrates a longitudinal cross-section of a housing for an example fluidic oscillator;

FIG. 11 illustrates a housing for an example fluidic oscillator;

FIG. 12 illustrates a longitudinal cross-section of a housing for an example fluidic oscillator; and

FIG. 13 illustrates a housing for an example fluidic oscillator.

DETAILED DESCRIPTION OF THE INVENTION

The present inventions relate to methods for controlling the migration of unconsolidated particulates in a portion of a subterranean formation, and more particularly, to the using pressure pulses to enhance the effectiveness of placement of a consolidation fluid in a portion of a subterranean formation. According to the method of the present invention, pressure pulses generated by a suitable apparatus enhance the penetration of a consolidation fluid into the portion of the subterranean formation.

The invention has particular applicability where the formation is a weakly consolidated formation. Some embodiments of the present invention provide methods for treating subterranean a formation comprising the steps of, placing a consolidation fluid into a well bore and in contact with a portion of a subterranean formation to be consolidated and then sending energy in the form of vibration or pressure pulses through the fluid and formation. Such energy changes affect the dilatancy of the pores within the formation and act, inter alia, to provide additional energy to help overcome the effects of surface tension and capillary pressure within the formation. By overcoming such effects, the fluid may be able to penetrate more deeply and uniformly into the formation. Moreover, the methods of the present invention may be used to increase the coverage of a treatment fluid into zones with different permeabilities, without the requiring the use of an additive diverter.

Pressure pulses are effected while the consolidation fluid is being injected. When the pressure pulse is delivered, well bore pressure is elevated to a pulsed pressure for the entire duration of the pulse. Generally, pulsed pressure is a pressure sufficient to at least partially dilate the pore spaces in the portion of the formation being treated to increase fluid mobility and temporarily lower the capillary pressure in the formation. Pulsed pressure generally ranges from about 10 psi to about 3,000 psi. After the pulse, well bore pressure returns to its original pressure. After a time, the pulse is repeated; the pulse therefore has a frequency of 1/time. Generally, the frequency is a frequency sufficient to encourage the consolidation fluid to substantially uniformly enter the pore spaces of the formation. Generally, the frequency ranges from about 0.001 Hz to about 1 Hz.

The methods are preferably performed with an apparatus comprising: (i) a fluidic oscillator; and (ii) a lower packer positioned below the fluidic oscillator. The lower packer isolates a portion of the wellbore from another portion below the lower packer. According to a presently most-preferred embodiment, the methods are preferably performed with an apparatus comprising: (i) a fluidic oscillator; (ii) an upper packer positioned above the fluidic oscillator; and (iii) a lower packer positioned below the fluidic oscillator. The upper packer and the lower packer above and below the fluidic oscillator create a movable isolation or “straddle packer” tool to further help with placement while injecting the consolidation fluid.

During injection, the upper and lower packers expand against the wellbore, casing, or liner to form an isolated interval in the wellbore, allowing the consolidation fluid to penetrate the entire interval. While not injecting, the upper and lower packers stay in their reduced size without exerting stress on the wellbore, casing, or liner, and allowing the tool to be moved without creating suction effects or causing fluid to flow back into the wellbore. The oscillating pressure generated by the fluidic oscillator helps enhance the penetration of the consolidating fluid into the formation.

The injection treatment to consolidate the near-wellbore formation preferably involves injecting the following fluids: (a) a pre-flush fluid to help condition the formation matrix and prepare the sand surface for accepting the consolidation fluid; (b) a consolidation fluid to treat the unconsolidated particles, usually sand, and help consolidate the unconsolidated formation; (c) a post-flush fluid to displace the consolidation fluid from the wellbore and to displace the excess consolidation fluid from occupying the pore spaces inside the matrix of the formation.

In another embodiment of the methods according to the inventions, the method and apparatus can be applied in treatment of proppant located at near-wellbore locations that has previously been placed in fractures. In another embodiment, the methods and apparatuses can be applied in treatment of gravel pack surrounding a wellbore.

In yet another embodiment, the near-wellbore formation can be treated with a consolidation fluid to transform it into a hardened, competent, impermeable mass. Highly conductive flow paths, such as propped fractures or slots can then be created by hydraulic fracturing or hydrojetting to reconnect the wellbore with the untreated formation outsize the near-wellbore region of the treatment.

Depending on the length and number of intervals to be treated, the placement sequence of treatment fluids, e.g., the pre-flush fluid, the consolidation fluid, and the post-flush fluid, is repeated to treat all the desired interval or intervals. In one example, a method of treating a portion of a subterranean formation includes the placement of the treatment fluids starting with treating a lowermost interval and stepwise moving upward to place treatment fluids at upper intervals until all the desired intervals are treated. As each successive treatment is performed, the tool is moved upward through the wellbore. After treatment of all the desired intervals with the tool, the tool is pulled out of the wellbore.

The methods and apparatuses can be used in either vertical or horizontal wellbores, in consolidated and unconsolidated formations, in “open-hole” and/or under reamed completions, as well as in cased wells. If used in a cased wellbore, the casing is perforated to provide for fluid communication with the wellbore.

DEFINITIONS

As used herein, the words “comprise,” “has,” and “include” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or parts of an assembly, subassembly, or structural element.

As used herein, the term “subterranean” includes below the surface of the earth or below the surface of the earth at the bottom of a body of water, such as a subsea surface.

The term “work tubing” means tubing extending down from a work platform at the wellhead down into the wellbore. The “work tubing” refers to jointed tubular members or coiled tubing that is used to move or support a tool or to supply fluid to a tool at a subterranean treatment location in a well.

As used herein, the term “inflatable” and similar terms mean that a body can be expanded with hydraulic fluid pressure to increase the size of the body.

The term “vertical wellbore” is used herein to mean the portion of a wellbore to be completed which is substantially vertical or deviated from vertical in an amount up to about 15°. The term “horizontal wellbore” is used herein to mean the portion of a wellbore to be completed is substantially horizontal, or at an angle from vertical, in the range of from about 75° to about 105°.

Since the present inventions are applicable in horizontal and inclined wellbores, the terms “upper,” “lower,” “top,” and “bottom,” as used herein are relative terms and are intended to apply with respect to the direction of the wellhead, where “upper” and similar terms are toward the wellhead and “lower” and similar terms are farther from the wellhead, regardless of whether the particular portion of a wellbore is vertical or horizontal.

If there is any conflict between the definition or usage of a term in this specification and the specification of another patent document incorporated herein by reference, the definition or usage of this specification will control.

Well Environment and Preferred-Embodiment of Tool Assembly

Referring more particularly to FIGS. 1D through 1D, wherein like reference characters are used throughout to refer to like or corresponding parts, there is shown one embodiment of an apparatus 10 according to the present inventions illustrating a method of treating a portion of a subterranean formation surrounding a wellbore in accordance with a method of the present inventions.

FIGS. 1A-1D illustrate a typical example of a downhole operating environment for the tool assembly 10. The operating environment is a wellbore 1 penetrating through a plurality of subterranean formations 2a, 2b, and 2c. The wellbore 1 can be open hole or have a liner or a casing. As illustrated in FIGS. 1D-1D, the wellbore has a casing 3. If present, a liner or casing has at selected intervals a plurality of perforations, or is slotted, or is screened to provide fluid communication between the interior of the wellbore 1 and the near wellbore region surrounding the wellbore. The near wellbore region of the subterranean formations can have been previously fractured or perforated according to techniques known in the art. For example, as illustrated in FIGS. 1D-1D, the casing 3 has a plurality of upper perforations 4a and a plurality of lower perforations 4b, and where the perforations extend radially outward from the wellbore into surrounding subterranean formations 2b and 2c.

The tool assembly 10 is operably connected to work tubing, which can be, for example, a jointed pipe 5. The jointed pipe 5 extends downward from the wellhead into the wellbore 1.

An annulus is defined between the tool assembly 10 and the interior wall of the wellbore. For example, as illustrated in FIGS. 1D-1D, annulus 6 is defined between the tool assembly 10 and the interior surface of the casing 3 of the wellbore 1.

In general, the tool assembly 10 has a straddle packer design for a fluidic oscillator 100. The presently most-preferred embodiment for the fluidic oscillator 100 is hereinafter described in detail. The straddle packer design includes an upper mandrel 12a of an upper packer, such as upper inflatable packer 14a and a lower mandrel 12b of a lower packer, such as lower inflatable packer 14b.

An inflatable packer is a type of packer that uses an inflatable bladder to expand the packer element against the casing or wellbore. Inflatable packers are capable of relatively large expansion ratios, an important factor in through-tubing work where the tubing size or completion components can impose a significant size restriction on devices designed to set in the casing or liner below the tubing. The inflatable seal elements should have sufficient compressibility to pass through the wellbore or a restricted tubing section and sufficient strength that when in an inflated condition it is adapted to substantially restrict, and preferably to completely shut off, fluid flow around the mandrel of the inflatable packer. Suitable inflatable seal elements are well-known in the art.

The inflatable seal elements should be sized to properly engage the inner wall of the largest-diameter open-hole wellbore, casing, liner, or other tubular in which the tool assembly 10 according to the present inventions is to operate and should be of sufficient length to substantially restrict flow of treatment fluids along the annulus 6 between the mandrel and the wellbore. The seal elements should also readily deflate or compress to a radial size to pass through the smallest internal diameter restrictions leading to the subterranean treatment location.

In the exemplary embodiment of the present inventions, the inflatable seal elements of the inflatable packers 14a and 14b are made from a rubber material. Important specifications to consider for selecting materials for inflatable seal elements include tensile strength, tensile modulus, elongation, tear strength, use temperature, thermal conductivity, and compressibility. One of ordinary skill in the art with the benefit of this disclosure will be able to determine the appropriate materials for the inflatable seal elements of the inflatable packers 14a and 14b.

In certain embodiments of the present inventions, the inflatable seal elements of the inflatable packers 14a and 14b will have a generally cylindrical shape as shown in FIGS. 1D-1D. In certain embodiments, however, the seal elements will have a constant cross section; in other embodiments such as shown, the cross section will vary along the length. In certain embodiments, the outer surface of the seal elements will have a smooth outer surface; in others, the outer surface could be comprised of a plurality of one or more ribs of fins. In certain exemplary embodiments, the end faces of the seal elements will be planar, concave or convex.

The seal elements of the inflatable packers 14a and 14b are selected to have an expanded diameter and length to restrict flow along the annulus 6 formed between the outside of the mandrels 12a and 12b, respectively and the interior wall of an open-hole wellbore or a casing or liner, such as the casing 3. Preferably, the seal elements contact the interior wall of the open-hole wellbore or the casing at the subterranean treatment location and have sufficient length to prevent flow through the annulus 6.

According to the present invention, instead of using a drop ball or series of tubing movements to operate each of the upper and lower inflatable packers, one or more hydraulic control lines, for example, hydraulic control lines 16a and 16b, are preferably used to operate the upper and lower inflatable packers 14a and 14b. Inflation and deflation of the upper and lower inflatable packers 14a and 14b is accomplished via hydraulic control lines 16a and 16b, respectively. The hydraulic control lines 16a and 16b are sturdy enough for inflation of the inflatable packers 14a and 14b. The hydraulic control line 16b to the lower inflatable packer 14b can be compressed between the upper inflatable packer 14a and the casing 3. This embodiment enables the packers 14a and 14b to inflate by application of pressure from a hydraulic fluid source at the wellhead (not shown) of the wellbore 1 or to deflate by reducing the hydraulic pressure.

It should be understood that the function of the hydraulic control lines 16a and 16b can be combined with the use of a single hydraulic control line that controls both the upper and lower inflatable packers 14a and 14b. It should further be understood that the hydraulic control line 16b for the lower inflatable packer 14b can be operatively connected to run through or along the upper mandrel 12a, whereby the hydraulic control line 16b does not need to pass between the upper inflatable packer 14a and the casing 3. It should be further understood that the hydraulic control line 16b for the lower inflatable packer 14b should be clamped or otherwise secured to the housing of the fluidic oscillator, whereby the hydraulic control line 16b does not obstruct any of the ports of the fluidic oscillator 100. In FIGS. 1A-D, for example, the hydraulic control lines are shown rotated 90 degrees for clarity of the drawing, but preferably would be clamped or otherwise secured away from the ports of the fluidic oscillator 100.

Currently, the embodiment of the invention illustrated in FIGS. 1D-1D is the presently most-preferred apparatus and method. This embodiment is preferred over injecting between “cup” or “compression” style packers because the swabbing effect is greatly reduced resulting in less of the consolidation fluid from being sucked out as a result of swabbing effect.

The upper mandrel 12a of the upper inflatable packer 14a is mechanically coupled by a collar 22 to work tubing, such as the jointed pipe 5. According to the illustrated embodiment, the work tubing is jointed pipe 5, but coiled tubing is also contemplated. The jointed pipe 5 is adapted and used to insert the tool assembly 10 though the wellbore 1 to a subterranean treatment location.

The fluidic oscillator 100 is operatively connected between the upper mandrel 12a of the upper inflatable packer 14a and the lower mandrel 12b of the lower inflatable packer 14b. One or more types of treatment fluid can be pumped from the surface through the jointed pipe 5, through the upper mandrel 12a of the upper inflatable packer 14a, and out through the fluidic oscillator 100 to treat a portion of the subterranean formation surrounding the wellbore at the location of the fluidic oscillator 100.

The lower end of the fluidic oscillator 100 can be operatively connected to the lower mandrel 12b of the lower inflatable packer. The fluid escaping from the lower end of the fluidic oscillator can be allowed to escape through the lower mandrel 12b or the lower mandrel 12b can have a cap to plug fluid flow therethrough. The cap 20 is optional, and may be used or not used according to job treatment design criteria as will be appreciated by those of skill in the art.

The tool assembly 10 has a run-in condition with the upper and lower packers 14a and 14b in a deflated condition. In this run-in condition, the tool assembly 10 can be run into the wellbore 1 to a desired depth or moved from one location to another within the wellbore.

The tool assembly 10 also has a set condition with the upper and lower packers 14a and 14b in an inflated condition. When inflated, the upper and lower inflatable packers 14a and 14b substantially isolate, and preferably completely isolate, the annulus 6 around the fluidic oscillator 100 from other portions of the wellbore 1 by sealing annuls 6 above and below the position of the fluidic oscillator 100 in the wellbore.

A treatment fluid, including, for example, a consolidation fluid as hereinafter described in detail, can be injected through the jointed pipe 5 and through the fluidic oscillator 100 of the tool assembly 10 in either the run-in condition or the set condition. Preferably, the between the packers into the wellbore area.

Referring to FIG. 1D in particular, the tool assembly 10 is illustrated in the wellbore 1 with the upper and lower inflatable packers 14a and 14b in a deflated, run-in condition. In FIG. 1B, the tool assembly 10 is illustrated with the upper and lower inflatable packers 14a and 14b in an inflated, set condition. The inflatable packers 14a and 14b are illustrated respectively positioned above and below lower perforations 4b and such that the fluidic oscillator 100 of the tool assembly 10 is positioned adjacent lower perforations 4b. In FIG. 1C, the tool assembly 10 is illustrated with the upper and lower packer again deflated and back in a run-in condition to again allow for movement of the tool assembly 10 through the wellbore. The tool assembly 10 can be completely removed from the wellbore 1 or moved to at least one other treatment location. FIG. 1D shows the tool assembly 10 is illustrated with the upper and lower inflatable packers 14a and 14b again in an inflated, set condition. This time, the inflatable packers 14a and 14b are illustrated respectively positioned above and below upper perforations 4a and such that the fluidic oscillator 100 of the tool assembly 10 is positioned adjacent the upper perforations 4a.

Treatment Methods of the Invention

A method of treating a portion of a subterranean formation penetrated by a wellbore is provided, the method comprising the steps of:

(a) moving a treatment tool through the wellbore on work tubing to a desired subterranean location, wherein the treatment tool comprises:

• • (i) a fluidic oscillator; and
  • (ii) a lower packer positioned below the fluidic oscillator;

(b) expanding the cross-section of the lower packer to engage the wellbore, thereby isolating a portion of the wellbore from another portion below the lower packer;

(c) injecting a consolidation fluid through the tubing and through the fluidic oscillator into the isolated portion of the wellbore;

(d) reducing the cross-section of the lower packer, thereby disengaging the tool from the wellbore.

According to a presently most-preferred embodiment, a method of treating a portion of a subterranean formation penetrated by a wellbore is provided, the method comprising the steps of:

(a) moving a treatment tool through the wellbore on work tubing to a desired subterranean location, wherein the treatment tool comprises:

• • (i) a fluidic oscillator;
  • (ii) an upper packer positioned above the fluidic oscillator; and
  • (iii) a lower packer positioned below the fluidic oscillator;

(b) expanding the cross-section of each of the upper packer and the lower packer to engage the wellbore, thereby isolating a portion of the wellbore between the upper packer and the lower packer;

(c) injecting a consolidation fluid through the tubing and through the fluidic oscillator into the isolated portion of the wellbore;

(d) reducing the cross-section of the upper packer and the lower packer, thereby disengaging the tool from the wellbore.

Thus, according to a preferred embodiment of the invention, a method is provided including the steps of moving the tool assembly 10 in a run-in condition to a desired position in a wellbore 1, setting the tool assembly 10 at the desired position to isolate a zone in the wellbore, treating the isolated zone with a consolidation fluid injected through the fluidic oscillator 100 of the tool assembly 10, and then operating the tool back to a run-in condition so that the tool assembly can again be moved through the wellbore. The method preferably includes repeating the process at least one additional time, whereby a different portion of the wellbore may be treated with a consolidation fluid according to the invention. Most preferably, the method includes treating the zone with a consolidation fluid.

According to one aspect, the present inventions provide apparatuses and methods for using hydraulic control lines for the purpose of setting inflation packers to effectively isolate the wellbore between packers for the purpose of injection consolidation fluids. The inflation fluid for the inflatable packers is independent of the consolidation fluid therefore eliminating problems with injecting the consolidation fluid into the packers, which could result in packer damage if the consolidation fluid is not thoroughly flushed or washed out of the packers.

Other variations of this concept could include running the hydraulic control lines inside the tubing to achieve the same effective. The concept could basically be reversed and achieve the same desired goal by using the tubing to set the packers and by using the control lines (inside or outside the tubing) to pump the consolidation fluid.

To provide through-tubing capacity, the packers of the tool assembly are deflated, compressed, or restrained in a size to fit through the restricted tubing and are inflated and/or released to expand to a size to function in the larger-diameter injection location. For example, the tool assembly 10 can be adapted to optionally to pass through restricted diameter production tubing (not shown in the Figures). Tools adapted to move through smaller tubing and operate in a larger-diameter wellbore portion are sometimes referred to as “through-tubing” tools.

The tool assembly 10 is a presently most-preferred example of a downhole tool that can be used to perform the treatment methods according to the present inventions. An example application of the methods of the inventions would be present when localized fluid injections are required at locations in a screened liner located below a smaller-diameter production tubing (not shown in the Figures). First, the tool 10 is assembled with inflatable seal elements for the inflatable packers 14a and 14b of a size to engage the walls of the casing 3. The inflatable packers are compressed and retained in the run-in position shown in FIG. 1D to allow passage through the smaller-diameter production tubing.

The tool assembly 10 is run-in to the wellbore on the work tubing, such as jointed tubing 5, to a desired subterranean treatment location.

As treatment fluid is pumped through the port 22, the fluid will be localized to the perforations into the formation at the screened liner 3 located between the inflatable packers 14a and 14b. In addition fluid injections a can be performed at multiple locations by axially moving the tool assembly 10. In addition, if desired, fluid can be injected as the tool is moved through the wellbore.

To retrieve the tool assembly 10 from the wellbore 1, the work tubing, such as jointed pipe 5, is retracted to pull the inflatable seal elements of the inflatable packers 14a and 14b into and through any smaller-diameter production tubing that may be present in the wellbore above a treatment location.

General Methods and Tools for Creating Pressure Changes

While there are several methods and tools capable of providing pressure or vibrational energy, according to the methods of the present invention, a fluidic oscillator is preferred. Fluidic oscillators create pressure changes that may be used to induce cyclical stresses (pressure pulses) in a subterranean formation. In such methods, the treatment fluid enters a switch body and is accelerated into a fluidic oscillator device. Examples of suitable fluidic oscillators are provided in U.S. Pat. Nos. 5,135,051, 5,165,438, and 5,893,383, each of which is hereby incorporated by reference. Generally, in such devices, the treatment fluid stream enters the oscillator and preferentially attaches to the outer wall of one of the fluid passageways and continues down the selected passageway to the outlet. As the flow passes a cross channel, a low pressure area is created which causes the main fluid stream to be interrupted and the flow to switch and attach to the other fluid passageway. The switch begins to oscillate which causes alternating “bursts” of fluid to be ejected into the well bore. As each “burst” is ejected, it forms a compression wave within the well bore fluid. As the wave passes through the formation and is reflected back, it induces dilation on the porosity of the formation matrix. Generally, the use of high frequency, low amplitude pressure pulses will focus energy primarily in the near wellbore region while low frequency, high amplitude pressure pulses may be used to achieve deeper penetration.

Presently Most-Preferred Fluidic Oscillator

The industry has taken a quantum leap with the release and commercial application of the next generation of fluidic oscillator near-wellbore stimulation service. The design is unique in its adaptation of the classical feedback loop oscillator design. One innovative design feature is the ability to tune the output frequency of this tool by scaling the oscillator pattern for optimum fluid placement efficiency and penetration as our knowledge and database of production results grows. Unlike other “use-as-is” fluidic oscillators this next generation fluidic oscillator design is “living” technology that can grow and adapt to field feedback.

The fluidic oscillator is a downhole device that generates alternating bursts of fluid. The device creates pressure waves within the wellbore and formation fluids that can (1) break up near-wellbore damage and (2) restore and enhance the permeability of the perforations and near-wellbore area. This tool incorporates the proven, classical feedback loop theory for generation of the Coanda effect.

Fluidic oscillators are available in virtually any Outer Diameter (“OD”) size and are adaptable to both jointed pipe and coiled tubing applications. The tools operate at an optimal pressure drop of approximately 2,000 psi and oscillate at a frequency between 300 to 600 Hz. The tools are rated to 400° F. and are suitable for sour gas service. Fluidic oscillators incorporate several design features that help improve reliability, function, and performance while reducing tool life-cycle costs. These features include:

A metal-to-metal, tapered seal—no moving parts or seals.

Side jets that maximize penetration energy by direct impingement on the casing or near wellbore.

Multi-angular fluid impingement.

Higher energy output over a narrower frequency range than conventional oscillators.

Turbulence created by side and down jets that helps lift debris out of the hole.

A down jet that clears debris, obstructions, or bridges while tripping into hole.

Adaptability for running on either coiled tubing or jointed pipe.

Customized inserts to maximize flow rate and pressures.

Replaceable inserts manufactured using modern high-tech electrical discharge machining (EDM) process.

Typical downhole applications for the fluidic oscillator include:

Removal of scale and other deposits from the near wellbore area, perforations, and screens. Removal can include:

• • Perforation damage
  • Mud and cement damage
  • Most scales
  • Emulsions
  • Drilling damage
  • Paraffin and asphaltenes
  • Formation fines
  • Water and gas blocks

Primary stimulation of high-permeability formations

Preparation for stimulation treatments

Preparation for gravel packing or frac packing

Alteration of injection profiles

Accurate placement of treating chemicals

Theory, Operation, and Applications of the Coanda Effect

The fluidic oscillator operation is based upon the Coanda effect. The Coanda, or “wall attachment” effect was discovered by Romanian aerodynamicist Henri-Marie Coanda in 1930. He observed that a stream of fluid emerging from a nozzle tends to follow a nearby curved or angled surface, if the curvature of the surface or angle the surface makes with the stream is not too sharp. This phenomenon is known as the Coanda effect and is exhibited in gases, liquids and slurries.

When applied correctly, the Coanda effect can be used as an engineering tool to make many useful devices. There have been many specific devices designed using the Coanda effect. These include propulsion systems, hydraulic pumps and motors, thermal devices, airfoils, fluid logic devices, and many other devices. Basic Coanda devices used in many applications include:

Fluidic Switches and Valves—Fluid flow is “switched” between two output ports and held there using the Coanda effect. The fluid continues to flow through a specific output port until the Coanda effect in that port is disrupted causing fluid to “lock” into the other output port, thus switching the flow. No moving parts are required.

Fluidic Oscillators—Fluid flow repeatedly switches between two or more flow paths without the use of any moving parts. A detailed description and analysis of one of these devices is presented in later sections.

Fluidic Flowmeters—A fluidic oscillator exhibits an oscillation frequency that is proportional to flow rate through the meter and detected by the meter's sensors.

Nozzles—Nozzles use internal fluidic oscillation to create directional and geometric changes in the exit jet, ejecting fluid in a specific pattern without the use of moving parts.

Technical Description of the Presently Most-Preferred Fluidic Oscillator

The fluidic oscillator discussed in this paper has been specifically designed for high-pressure, submerged operation. Additionally, the fluidic oscillator pattern is optimized for use in a relatively slim tool design. A presently most-preferred embodiment for a fluidic oscillator for use according to the present invention is hereinafter described in more detail with reference to FIGS. 2-13.

In this design a narrow inlet throat is used to create a jet which exits into the interior of the oscillator. The formed jet “sticks” to one of the angled interior surfaces shown by virtue of the Coanda effect described earlier. After the jet attaches to a surface, the fluid that forms the jets travels along the surface until it hits the entrance to the feedback loop. A large portion of the fluid enters the feedback loop and exits the outlet port attached to the feedback loop. Some of the fluid travels past the outlet port and continues through the feedback loop where it disrupts the attached jet and deflects it towards the other angled surface. The jet then attaches to the opposite angled surface and the process continuously repeats itself, creating a steady oscillation of flow between the outlet ports. The frequency of oscillation is related to the time it takes the fluid in the switched jet to travel along the angled surface to the inlet of the feedback loop. The transit time for the jet fluid is a function of the jet fluid velocity and the length of the angled surface. The lower the jet fluid velocity, the lower the resulting oscillation frequency will be. Also, the longer the length of the angled surface the lower the frequency will be.

CFD Analysis of the Next Generation Fluidic Oscillator

The fluidic oscillator was extensively analyzed using computational fluid dynamics (CFD) analysis software to fully understand and optimize the tool's performance. Tools of several different sizes were simulated over a wide range of flow rates. This analysis allowed for subtle changes to the oscillator geometries, which improve performance and help ensure reliable operation over the range of flow rates. The boundary conditions for the model consisted of constant pressure applied at the inlet to the oscillator and zero pressure applied to the outlet. The properties of the working fluid used in the modeling were those of water. Pressures ranging from 25 to 4,000 psi were used, resulting in flow rates between a few gallons per minute and several barrels per minute, depending on tool size.

Experimental Testing

Several sizes of tools were built and tested. These devices were tested experimentally. In each test a specific fluid pump rate was established and held constant while the tool was lowered or lifted past a high-speed pressure transducer. Excellent correlation between the experimentally measured oscillation frequencies and the predicted CFD results was observed. Additionally, in both the experimental and theoretical results, a fairly linear relationship between flow rate and pressure were observed when flowrates were not excessively low. This is consistent with classic feedback fluidic oscillator theory. See Kirshner, J. M., Katz, S.: “Design Theory of Fluidic Components,” Academic Press, New York (1975) 14.

Manufacturing Challenges

Manufacturability, cost, and product cycle life were all factors considered during the design of the fluidic oscillator. Design goals included a geometry that allowed for replaceable/interchangeable inserts, metal-to-metal seal, and adaptability for use with other in-house tool systems. The resulting geometry was a unique, tapered insert design, as hereinafter described in detail.

Manufacturing of the fluidic oscillator's internal and external tapered, rectangular profiles required a manufacturing approach even the most advanced NC milling methods could not meet. The manufacturing process requirements were to:

Hold exacting tolerances on both the case and insert within 0.0005 inches to maintain a metal-to-metal seal.

Allow for progressive radiuses along the edges of both the case and insert.

Be cost effective.

Allow for alternative insert materials, such as thermoset plastics or composites.

The solution to machine these profiles was found in the using the electrical discharge machining (“EDM”) process.

The classical feedback loop pattern on the tapered insert itself presented another machining challenge. The pattern depth-to-width ratio was much greater than typical mill end-cutters are designed. Flexure can cause them to snap during the machining process. This problem was overcome by using special cutters designed for high depth-to-width cutter diameter ratios.

Advanced high-strength, high-temperature thermoset plastics are being prototype tested for the tapered insert. The inserts are precision injection molded to allow for a perfect fit, matching that of the current steel insert.

Detailed Description of Presently Most-Preferred Embodiment of Fluidic Oscillator

FIG. 2 illustrates an example fluidic oscillator 100. Example fluidic oscillator 100 comprises a housing 200 that encloses at least one insert 300. Insert 300 contains flowpath 302, which generates the oscillation effect that drives the fluid pulses. FIG. 2 displays a partially cutaway view of housing 200 to better display insert 300 and flowpath 302. The example housing shown in FIG. 2 is cylindrical, with a circular cross-section; housing 200 may alternatively take other forms, including, but not limited to, a bar-shaped form with a rectangular cross-section. Alternatively, housing 200 may include multiple inserts, as discussed in more detail later in this disclosure. A fluid flowline 400 supplies fluid to fluidic oscillator 100. Fluid flowline 400 may fit inside housing 100 or alternatively connect to fluidic oscillator 100 via a transitional piece (not shown in FIG. 2).

Housing 200 and insert 300 may be formed of any material capable of withstanding the environment in which fluidic oscillator 100 will be used. For example, housing 200 and insert 300 may be formed of metal. Alternatively, housing 200 and insert 300 may be formed of a phenolic plastic capable of withstanding a downhole environment. Fluidic oscillator 100's design allows the user to replace insert 300 without replacing fluidic oscillator 100 entirely. That is, if flowpath 302 erodes after heavy use, insert 300 may be replaced and housing 200 may be reused. The use of an insert 300 also permits customization of the flowpath in the field.

FIGS. 3 and 4 illustrate an example insert 300. As shown in FIG. 3, insert 300 has flowpath 302 cut into its upper surface 301; flowpath 302 may be created through traditional machining processes, such as milling, casting, or molding or may be generated through an Electrical Discharge Machining (EDM) process. For ease of illustration, FIG. 4 illustrates a plan view of flowpath 302 in upper surface 301. Fluid supplied by fluid flowline 400 enters into flowpath 302 via interior flowline 303 and passes through inlet 304. Interior flowline 303 may decrease in width as it approaches inlet 304 to form a focused jet as it enters inlet 304. The fluid passes through inlet 304 into chamber 305. Chamber 305 is defined by two outwardly projecting sidewalls 306 and 307 and has an upstream end 308 and a downstream end 309. A feedback cavity 310 is disposed at downstream end 309.

Flowpath 302 may have the configuration of the flowpath described and depicted in the application for U.S. patent entitled “Apparatus and Method for Creating Pulsating Fluid Flow, and Method of Manufacture for the Apparatus,” Ser. No. 10/808,986 filed on Mar. 25, 2004, U.S. Patent Publication No. 20050214147 published Sep. 29, 2005, assigned to the assignee of this disclosure. The fluid forms a jet as it streams from inlet 304 into chamber 305 in example insert 300. As the jet leaves inlet 304, the fluid tends to cling to one of the two outwardly projecting sidewalls 306 or 307. This tendency is a result of the well-documented phenomenon known as the “Coanda effect.” When the fluid exits inlet 304 as a jet into chamber 305, it draws any fluid between the jet and one of the two outwardly projecting sidewalls 306 or 307 into the jet. For example, the jet may first draw fluid between the jet and outwardly projecting sidewall 306 into the jet. The temporary absence of fluid between the jet and outwardly projecting sidewall 306 creates a low-pressure region. Before the ambient pressure in chamber 305 can restore pressure to this region, the jet is drawn to outwardly projecting sidewall 306 and clings to its surface. The result of this Coanda effect is that the fluid enters chamber 305 along one of the outwardly projecting sidewalls 306 or 307, rather than through the center of chamber 305.

The pulsating action of the fluid flow generated by exemplary fluidic oscillator 100 arises from switches in the fluid flow from along outwardly projecting sidewall 306 to along outwardly projecting sidewall 307, and vice versa. At least two feedback passages 311 and 312 are disposed on opposite sides of chamber 305 to help achieve these switches. Two opposed entrances 313 and 314 leave from downstream end 309 of chamber 305. Two opposed exits 315 and 316 to feedback passages 311 and 312 join upstream end 308 of chamber 305. To continue with the example of the previous paragraph, a portion of the fluid traveling alongside outwardly projecting sidewall 306 will reach opposed entrance 313 and be diverted into feedback passage 311. Most of the fluid that enters feedback passage 311 will exit insert 300 through exit flowline 317, as discussed later in this disclosure in more detail. The remaining fluid that enters feedback passage 311, however, will return to chamber 305 through opposed exit 315. The entry of this fluid into chamber 305 disturbs the path of the jet of fluid issuing from inlet 304 such that the jet no longer adheres to outwardly projecting sidewall 306. The jet of fluid instead will adhere to outwardly projecting sidewall 307 in the same manner as it adhered to outwardly projecting sidewall 306.

The jet of fluid will then travel along outwardly projecting sidewall 307, and a portion of the fluid will enter feedback passage 312 through opposed entrance 314. Most of the fluid will exit insert 300 through exit flowline 318, as discussed in detail later in this disclosure. The remaining fluid in feedback passage 312 will continue to opposed exit 316 and return to chamber 305. As with the fluid entering chamber 305 from opposed exit 315, the fluid passing through opposed exit 316 will disturb the flow of fluid along the surface of outwardly projecting sidewall 307. The fluid will then switch from traveling alongside outwardly projecting sidewall 307 to traveling alongside outwardly projecting sidewall 306, and the cycle will repeat.

At any time when fluid flows along outwardly projecting sidewall 306 and through feedback passage 311, no fluid flows along outwardly projecting sidewall 307 or through feedback passage 312. The converse is also true: no fluid flows along outwardly projecting sidewall 306 or through feedback passage 311 while fluid flows along outwardly projecting sidewall 307 and through feedback passage 312. This oscillation of fluid from one half of insert 300 to the other helps create the desired pulsating fluid flow. In particular, as fluid travels through either feedback passage 311 or 312, exit flowline 317 or 318, respectively, will draw off a portion of the passing fluid. Fluid entering exit flowline 317 or 318 will exit insert 300. The effect of the oscillation of the fluid between outwardly projecting sidewall 306 and outwardly projecting sidewall 307 is that fluid will exit through only one exit flowline 317 or 318 at a time. Thus insert 300 will emit pulses of fluid from one side to the other, in succession.

Exit flowlines 317 and 318 in this example insert 300 are perpendicular to feedback passages 311 and 312, respectively. Exit flowlines 317 and 318 may, however, take any number of different paths, as described in the application for U.S. patent entitled “Apparatus and Method for Creating Pulsating Fluid Flow, and Method of Manufacture for the Apparatus,” Ser. No. 10/808,986 filed on Mar. 25, 2004, U.S. Patent Publication No. 20050214147 published Sep. 29, 2005, assigned to the assignee of this disclosure. The best path for the exit flowlines will depend upon how the apparatus will be used, as will be readily apparent to a person of ordinary skill in the art having the benefit of this disclosure.

Feedback cavity 310, disposed at downstream end 309 of chamber 305, further promotes the oscillation of fluid flow in insert 300. While a portion of the fluid traveling along outwardly projecting sidewalls 306 and 307 is directed into opposed entrances 313 and 314, the remainder of the fluid exits chamber 305 into feedback cavity 310. If the fluid enters feedback cavity 310 after traveling along outwardly projecting sidewall 306, the fluid will follow a clockwise path around feedback cavity sidewall 319 and return to chamber 305 near outwardly projecting sidewall 307. This fluid flow will destabilize the fluid flow near outwardly projecting sidewall 307. The added instability amplifies the oscillation effect produced by feedback passage 311 by drawing fluid to outwardly projecting sidewall 307 from outwardly projecting sidewall 306. The cycle then reverses, with fluid entering from outwardly projecting sidewall 307 and following a counterclockwise path in feedback cavity 310 to near outwardly projecting sidewall 306. Example feedback cavity 310 has a rounded shape. Any volume that extends beyond opposed entrances 313 and 314 may serve as a feedback cavity 310, regardless of the shape the volume assumes. A forward jet 320 may be present at feedback cavity sidewall 319. Forward jet 320 may be useful for the well bore and fluid flowline cleaning applications. For example, if fluidic oscillator 100 travels within a fluid flowline with forward jet 320 at the leading edge, forward jet 320 will jet fluid ahead of fluidic oscillator 100 and could thus clear debris from the path of fluidic oscillator 100. Forward jet 320 should have a smaller cross-section than feedback passages 311 and 312, to prevent disturbances to the pulsating action.

Insert 300 is wedge-shaped, as illustrated in FIG. 3. Upper surface 301, a corresponding lower surface 330 (not shown in FIG. 3), and two side surfaces 331 and 332 (not shown). Each side slopes such that insert 300 is narrower at its downstream end 333 than at its upstream end 334. The angle of the slope may vary between approximately 0 degrees to approximately 15 degrees. The slope of upper surface 301 and lower surface 330 is made obvious in FIG. 5, which illustrates a side view of insert 300. The tapered wedge shape of insert 300 has the benefit of allowing flowpath 302 to maintain a substantially constant depth inside insert 300 with only a gradual slope downstream in the height of the walls that form flowpath 302. The walls maintain a substantially constant height across the width of the insert at any one location along the fluid flowpath. Rather, the height of the walls will only gradually decrease toward the downstream end of the insert. In contrast, if insert 300 assumed a cylindrical form, the height of the walls that form flowpath 302 would be much shorter near feedback outlets 317 and 318 than near chamber 305. Moreover, the wedge shape for the insert provides a substantially flat surface for flowpath 302. This configuration enhances the performance of fluidic oscillator 100, as compared to, for example, a cylindrical insert which would have a curved surface for the flowpath.

The wedge shape is also more conducive to precision EDM processes and field customization than a cylindrical form would be. Inserts may be customized for particular jobs; a given fluidic oscillator may include multiple inserts that may be switched before use, even on site, depending on the job. The wedge shape of insert 300 also permits a tight, fluid-impermeable fit directly between housing 200 and insert 300. That is, insert 300 may be designed to fit inside housing 200 such that all the outside surfaces of insert 300 directly contact the interior of housing 200 and create a fluid-tight seal that prevents any fluid from escaping from flowpath 302. The direct housing-to-insert seal eliminates the need for any additional sealing structure and thus eliminates a manufacturing and operational variable.

The insert may also assume alternate forms. For example, the insert may be a rectangular block, rather than a wedge. FIG. 6 illustrates a top view of a rectangular insert 340. A tab 341 may be provided to lock insert 340 into housing 200, which is discussed in greater detail later in this disclosure. The rectangular profile of insert 340 is evident in FIG. 7, which illustrates a side view of insert 340. A second tab 342 may also be provided on lower surface 343 of insert 340. FIG. 8 displays another sample insert 350. Insert 350 provides enough material to support walls 351 to surround flowpath 302, but not very much more. Thus, rather than assuming a wedge or rectangular shape, the insert assumes a shape that models flowpath 302. Interior flowline 353 and two exit flowlines 354 and 355 may attach to specially-adapted notches in housing 200, which is discussed in greater detail later in this disclosure.

Fluidic oscillator 100 also comprises a housing 200. Examples of housing 200 are illustrated in FIGS. 9, 10, 11 and 12. FIG. 9 illustrates an outside view of a housing 200. Port 201 is positioned to allow fluid exiting from exit flowline 317 in insert 300 to escape housing 200. Although not visible in FIG. 9, a corresponding port 202 is located on the opposite side of housing 200 (180 degrees from port 201). Port 202 allows fluid exiting from exit flowline 318 in insert 300 to escape housing 200. Slot 203 in end 204 of housing 200, fits directly around downstream end 333 of insert 300.

FIG. 10 illustrates longitudinal cross-sectional views of housing 200, with ports 201 and 202 at the top and bottom, respectively. To achieve the fluid-tight seal, housing 200 may include a recess 205 that is shaped to receive and directly engage the insert. The insert fits inside recess 205, sliding in through entrance 206 and slot 203 until the insert mates with the housing. If the insert is tapered, like insert 300, recess 205 must be tapered to fit closely over the insert. Surfaces 301, 330, 331 and 332 of insert 300, shown in FIGS. 3, 4, and 5, for example, may create a fluid-tight seal with an inside surface 210 of housing 200. This fluid-tight seal eliminates the need for any intervening sealing mechanism. Just inside entrance 206, a series of threads 208 is provided to engage a fluid flowline 400; the threads may be either male or female or otherwise customized to accommodate a specific fluid flowline 400. FIG. 11 illustrates an additional cross-sectional view of housing 200 in which housing 200 has been rotated about a central longitudinal axis from the view in FIG. 10.

If the insert is not tapered, but instead is rectangular, the recess may also be rectangular. The recess may also be rectangular, or otherwise shaped, to accept an insert that is formed only of the walls of the flowpath, such as insert 350. Another example housing 250 for insert 350 is shown in FIG. 12; recess 251 is rectangular. Housing 200 may then have slots 252 and 253 that are specially adapted to accommodate and retain exit flowlines 354 and 355.

Alternatively, a fluidic oscillator may include a housing designed to accommodate multiple inserts. Such a fluidic oscillator may allow for a higher volume of fluid to pass through this example fluidic oscillator than fluidic oscillators including only one insert, thereby increasing, for example, the potential injection rate of consolidating fluid through the fluidic oscillator. FIG. 13 illustrates an example housing 260 with four recesses 261, 262, 263, and 264 spaced substantially evenly about a central longitudinal axis of housing 260, or approximately 60 degrees apart. Support 265 of housing 260 maintains the spacing between each insert and provides the structure for recesses 261, 262, 263, and 264. Each recess 261, 262, 263, or 264 may enclose one insert, similar to the recesses described previously in this disclosure. Alternatively, housing 260 may include recesses large enough to accommodate more than one insert. As one of ordinary skill in the art having the benefit of this disclosure will realize, housing 260 may enclose any number of inserts spaced at any interval; the housing 260 shown in FIG. 13 is merely an example. The inserts will contain flowpaths that generate fluid pulses in the manner described earlier in this disclosure.

Housing 260 also provides at least one port, not shown in FIG. 13, to allow fluid to escape from each insert, similar to ports 201 and 202. A single high-volume port may be provided. However, multiple ports for the example fluidic oscillator may be aligned such that fluid jets from housing 260 in multiple directions at the same time. For instance, housing 260 may have multiple ports for each insert, allowing the fluidic oscillator to jet fluid in substantially 360 degrees.

III. Consolidation Fluids Suitable for Use in the Present Invention

Consolidation fluids suitable for use in the present invention generally comprise at last one of a tackifying agent, curable resin, a gelable composition, or a combination thereof. Usually, the consolidation fluid will additionally comprise a suitable diluent or solvent for diluting or dissolving the tackifying agent, curable resin, gelable composition, or combination thereof. In some embodiments of the present invention, the viscosity of the consolidation fluid is controlled to less than about 100 cP, preferably less than about 50 cP, and still more preferably less than about 10 cP.

A. Consolidation Fluids—Tackifying Agents

Tackifying agents suitable for use in the consolidation fluids of the present invention comprise any compound that, when in liquid form or in a solvent solution, will form a non-hardening coating upon a particulate. A particularly preferred group of tackifying agents comprise polyamides that are liquids or in solution at the temperature of the subterranean formation such that they are, by themselves, non-hardening when introduced into the subterranean formation. A particularly preferred product is a condensation reaction product comprised of commercially available polyacids and a polyamine. Such commercial products include compounds such as mixtures of C₃₆ dibasic acids containing some trimer and higher oligomers and also small amounts of monomer acids that are reacted with polyamines. Other polyacids include trimer acids, synthetic acids produced from fatty acids, maleic anhydride, acrylic acid, and the like. Such acid compounds are commercially available from companies such as Witco Corporation, Union Camp, Chemtall, and Emery Industries. The reaction products are available from, for example, Champion Technologies, Inc. and Witco Corporation. Additional compounds which may be used as tackifying compounds include liquids and solutions of, for example, polyesters, polycarbonates and polycarbamates, natural resins such as shellac and the like. Other suitable tackifying agents are described in U.S. Pat. No. 5,853,048 issued to Weaver, et al. and U.S. Pat. No. 5,833,000 issued to Weaver, et al., the relevant disclosures of which are herein incorporated by reference.

Tackifying agents suitable for use in the present invention may be either used such that they form non-hardening coating or they may be combined with a multifunctional material capable of reacting with the tackifying compound to form a hardened coating. A “hardened coating” as used herein means that the reaction of the tackifying compound with the multifunctional material will result in a substantially non-flowable reaction product that exhibits a higher compressive strength in a consolidated agglomerate than the tackifying compound alone with the particulates. In this instance, the tackifying agent may function similarly to a hardenable resin. Multifunctional materials suitable for use in the present invention include, but are not limited to, aldehydes such as formaldehyde, dialdehydes such as glutaraldehyde, hemiacetals or aldehyde releasing compounds, diacid halides, dihalides such as dichlorides and dibromides, polyacid anhydrides such as citric acid, epoxides, furfuraldehyde, glutaraldehyde or aldehyde condensates and the like, and combinations thereof. In some embodiments of the present invention, the multifunctional material may be mixed with the tackifying compound in an amount of from about 0.01 to about 50 percent by weight of the tackifying compound to effect formation of the reaction product. In some preferable embodiments, the compound is present in an amount of from about 0.5 to about 1 percent by weight of the tackifying compound. Suitable multifunctional materials are described in U.S. Pat. No. 5,839,510 issued to Weaver, et al., the relevant disclosure of which is herein incorporated by reference.

Solvents suitable for use with the tackifying agents of the present invention include any solvent that is compatible with the tackifying agent and achieves the desired viscosity effect. The solvents that can be used in the present invention preferably include those having high flash points (most preferably above about 125° F.). Examples of solvents suitable for use in the present invention include, but are not limited to, butylglycidyl ether, dipropylene glycol methyl ether, butyl bottom alcohol, dipropylene glycol dimethyl ether, diethyleneglycol methyl ether, ethyleneglycol butyl ether, methanol, butyl alcohol, isopropyl alcohol, diethyleneglycol butyl ether, propylene carbonate, d'limonene, 2-butoxy ethanol, butyl acetate, furfuryl acetate, butyl lactate, dimethyl sulfoxide, dimethyl formamide, fatty acid methyl esters, and combinations thereof. It is within the ability of one skilled in the art, with the benefit of this disclosure, to determine whether a solvent is needed to achieve a viscosity suitable to the subterranean conditions and, if so, how much.

B. Consolidation Fluids—Curable Resins

Resins suitable for use in the consolidation fluids of the present invention include all resins known in the art that are capable of forming a hardened, consolidated mass. Many such resins are commonly used in subterranean consolidation operations, and some suitable resins include two component epoxy based resins, novolak resins, polyepoxide resins, phenolaldehyde resins, urea-aldehyde resins, urethane resins, phenolic resins, furan resins, furan/furfuryl alcohol resins, phenolic/latex resins, phenol formaldehyde resins, polyester resins and hybrids and copolymers thereof, polyurethane resins and hybrids and copolymers thereof, acrylate resins, and mixtures thereof. Some suitable resins, such as epoxy resins, may be cured with an internal catalyst or activator so that when pumped down hole, they may be cured using only time and temperature. Other suitable resins, such as furan resins generally require a time-delayed catalyst or an external catalyst to help activate the polymerization of the resins if the cure temperature is low (i.e., less than 250° F.), but will cure under the effect of time and temperature if the formation temperature is above about 250° F., preferably above about 300° F. It is within the ability of one skilled in the art, with the benefit of this disclosure, to select a suitable resin for use in embodiments of the present invention and to determine whether a catalyst is required to trigger curing.

Any solvent that is compatible with the resin and achieves the desired viscosity effect is suitable for use in the present invention. Preferred solvents include those listed above in connection with tackifying compounds. It is within the ability of one skilled in the art, with the benefit of this disclosure, to determine whether and how much solvent is needed to achieve a suitable viscosity.

C. Consolidation Fluids—Gelable Compositions

Gelable compositions suitable for use in the present invention include those compositions that cure to form a semi-solid, immovable, gel-like substance. The gelable composition may be any gelable liquid composition capable of converting into a gelled substance capable of substantially plugging the permeability of the formation while allowing the formation to remain flexible. As referred to herein, the term “flexible” refers to a state wherein the treated formation is relatively malleable and elastic and able to withstand substantial pressure cycling without substantial breakdown of the formation. Thus, the resultant gelled substance stabilizes the treated portion of the formation while allowing the formation to absorb the stresses created during pressure cycling. As a result, the gelled substance may aid in preventing breakdown of the formation both by stabilizing and by adding flexibility to the treated region. Examples of suitable gelable liquid compositions include, but are not limited to, (1) gelable resin compositions, (2) gelable aqueous silicate compositions, (3) crosslinkable aqueous polymer compositions, and (4) polymerizable organic monomer compositions.

1. Consolidation Fluids—Gelable Compositions—Gelable Resin Compositions

Certain embodiments of the gelable liquid compositions of the present invention comprise gelable resin compositions that cure to form flexible gels. Unlike the curable resin compositions described above, which cure into hardened masses, the gelable resin compositions cure into flexible, gelled substances that form resilient gelled substances. Gelable resin compositions allow the treated portion of the formation to remain flexible and to resist breakdown.

Generally, the gelable resin compositions useful in accordance with this invention comprise a curable resin, a diluent, and a resin curing agent. When certain resin curing agents, such as polyamides, are used in the curable resin compositions, the compositions form the semi-solid, immovable, gelled substances described above. Where the resin curing agent used may cause the organic resin compositions to form hard, brittle material rather than a desired gelled substance, the curable resin compositions may further comprise one or more “flexibilizer additives” (described in more detail below) to provide flexibility to the cured compositions.

Examples of gelable resins that can be used in the present invention include, but are not limited to, organic resins such as polyepoxide resins (e.g., Bisphenol a-epichlorihydrin resins), polyester resins, urea-aldehyde resins, furan resins, urethane resins, and mixtures thereof. Of these, polyepoxide resins are preferred.

Any solvent that is compatible with the gelable resin and achieves the desired viscosity effect is suitable for use in the present invention. Examples of solvents that may be used in the gelable resin compositions of the present invention include, but are not limited to, phenols; formaldehydes; furfuryl alcohols; furfurals; alcohols; ethers such as butyl glycidyl ether and cresyl glycidyl etherphenyl glycidyl ether; and mixtures thereof. In some embodiments of the present invention, the solvent comprises butyl lactate. Among other things, the solvent acts to provide flexibility to the cured composition. The solvent may be included in the gelable resin composition in an amount sufficient to provide the desired viscosity effect.

Generally, any resin curing agent that may be used to cure an organic resin is suitable for use in the present invention. When the resin curing agent chosen is an amide or a polyamide, generally no flexibilizer additive will be required because, inter alia, such curing agents cause the gelable resin composition to convert into a semi-solid, immovable, gelled substance. Other suitable resin curing agents (such as an amine, a polyamine, methylene dianiline, and other curing agents known in the art) will tend to cure into a hard, brittle material and will thus benefit from the addition of a flexibilizer additive. Generally, the resin curing agent used is included in the gelable resin composition, whether a flexibilizer additive is included or not, in an amount in the range of from about 5% to about 75% by weight of the curable resin. In some embodiments of the present invention, the resin curing agent used is included in the gelable resin composition in an amount in the range of from about 20% to about 75% by weight of the curable resin.

As noted above, flexibilizer additives may be used, inter alia, to provide flexibility to the gelled substances formed from the curable resin compositions. Flexibilizer additives may be used where the resin curing agent chosen would cause the gelable resin composition to cure into a hard and brittle material—rather than a desired gelled substance. For example, flexibilizer additives may be used where the resin curing agent chosen is not an amide or polyamide. Examples of suitable flexibilizer additives include, but are not limited to, an organic ester, an oxygenated organic solvent, an aromatic solvent, and combinations thereof. Of these, ethers, such as dibutyl phthalate, are preferred. Where used, the flexibilizer additive may be included in the gelable resin composition in an amount in the range of from about 5% to about 80% by weight of the gelable resin. In some embodiments of the present invention, the flexibilizer additive may be included in the curable resin composition in an amount in the range of from about 20% to about 45% by weight of the curable resin.

2. Consolidation Fluids—Gelable Compositions—Gelable Aqueous Silicate Compositions

In other embodiments, the consolidation fluids of the present invention may comprise a gelable aqueous silicate composition. Generally, the gelable aqueous silicate compositions that are useful in accordance with the present invention generally comprise an aqueous alkali metal silicate solution and a temperature activated catalyst for gelling the aqueous alkali metal silicate solution.

The aqueous alkali metal silicate solution component of the gelable aqueous silicate compositions generally comprise an aqueous liquid and an alkali metal silicate. The aqueous liquid component of the aqueous alkali metal silicate solution generally may be fresh water, salt water (e.g., water containing one or more salts dissolved therein), brine (e.g., saturated salt water), seawater, or any other aqueous liquid that does not adversely react with the other components used in accordance with this invention or with the subterranean formation. Examples of suitable alkali metal silicates include, but are not limited to, one or more of sodium silicate, potassium silicate, lithium silicate, rubidium silicate, or cesium silicate. Of these, sodium silicate is preferred. While sodium silicate exists in many forms, the sodium silicate used in the aqueous alkali metal silicate solution preferably has a Na₂O-to-SiO₂ weight ratio in the range of from about 1:2 to about 1:4. Most preferably, the sodium silicate used has a Na₂O-to-SiO₂ weight ratio in the range of about 1:3.2. Generally, the alkali metal silicate is present in the aqueous alkali metal silicate solution component in an amount in the range of from about 0.1% to about 10% by weight of the aqueous alkali metal silicate solution component.

The temperature-activated catalyst component of the gelable aqueous silicate compositions is used, inter alia, to convert the gelable aqueous silicate compositions into the desired semi-solid, immovable, gelled substance described above. Selection of a temperature-activated catalyst is related, at least in part, to the temperature of the subterranean formation to which the gelable aqueous silicate composition will be introduced. The temperature-activated catalysts that can be used in the gelable aqueous silicate compositions of the present invention include, but are not limited to, ammonium sulfate (which is most suitable in the range of from about 60° F. to about 240° F.); sodium acid pyrophosphate (which is most suitable in the range of from about 60° F. to about 240° F.); citric acid (which is most suitable in the range of from about 60° F. to about 120° F.); and ethyl acetate (which is most suitable in the range of from about 60° F. to about 120° F.). Generally, the temperature-activated catalyst is present in the gelable aqueous silicate composition in the range of from about 0.1% to about 5% by weight of the gelable aqueous silicate composition.

3. Consolidation Fluids—Gelable Compositions—Crosslinkable Aqueous Polymer Compositions

In other embodiments, the consolidation fluid of the present invention comprises a crosslinkable aqueous polymer compositions. Generally, suitable crosslinkable aqueous polymer compositions comprise an aqueous solvent, a crosslinkable polymer, and a crosslinking agent. Such compositions are similar to those used to form gelled treatment fluids, such as fracturing fluids, but, according to the methods of the present invention, they are not exposed to breakers or de-linkers and so they retain their viscous nature over time.

The aqueous solvent may be any aqueous solvent in which the crosslinkable composition and the crosslinking agent may be dissolved, mixed, suspended, or dispersed therein to facilitate gel formation. For example, the aqueous solvent used may be fresh water, salt water, brine, seawater, or any other aqueous liquid that does not adversely react with the other components used in accordance with this invention or with the subterranean formation.

Examples of crosslinkable polymers that can be used in the crosslinkable aqueous polymer compositions include, but are not limited to, carboxylate-containing polymers and acrylamide-containing polymers. Preferred acrylamide-containing polymers include polyacrylamide, partially hydrolyzed polyacrylamide, copolymers of acrylamide and acrylate, and carboxylate-containing terpolymers and tetrapolymers of acrylate. Additional examples of suitable crosslinkable polymers include hydratable polymers comprising polysaccharides and derivatives thereof and that contain one or more of the monosaccharide units galactose, mannose, glucoside, glucose, xylose, arabinose, fructose, glucuronic acid, or pyranosyl sulfate. Suitable natural hydratable polymers include, but are not limited to, guar gum, locust bean gum, tara, konjak, tamarind, starch, cellulose, karaya, xanthan, tragacanth, and carrageenan, and derivatives of all of the above. Suitable hydratable synthetic polymers and copolymers that may be used in the crosslinkable aqueous polymer compositions include, but are not limited to, polyacrylates, polymethacrylates, polyacrylamides, maleic anhydride, methylvinyl ether polymers, polyvinyl alcohols, and polyvinylpyrrolidone. The crosslinkable polymer used should be included in the crosslinkable aqueous polymer composition in an amount sufficient to form the desired gelled substance in the subterranean formation. In some embodiments of the present invention, the crosslinkable polymer is included in the crosslinkable aqueous polymer composition in an amount in the range of from about 1% to about 30% by weight of the aqueous solvent. In another embodiment of the present invention, the crosslinkable polymer is included in the crosslinkable aqueous polymer composition in an amount in the range of from about 1% to about 20% by weight of the aqueous solvent.

The crosslinkable aqueous polymer compositions of the present invention further comprise a crosslinking agent for crosslinking the crosslinkable polymers to form the desired gelled substance. In some embodiments, the crosslinking agent is a molecule or complex containing a reactive transition metal cation. A most preferred crosslinking agent comprises trivalent chromium cations complexed or bonded to anions, atomic oxygen, or water. Examples of suitable crosslinking agents include, but are not limited to, compounds or complexes containing chromic acetate and/or chromic chloride. Other suitable transition metal cations include chromium VI within a redox system, aluminum III, iron II, iron III, and zirconium IV.

The crosslinking agent should be present in the crosslinkable aqueous polymer compositions of the present invention in an amount sufficient to provide, inter alia, the desired degree of crosslinking. In some embodiments of the present invention, the crosslinking agent is present in the crosslinkable aqueous polymer compositions of the present invention in an amount in the range of from about 0.01% to about 5% by weight of the crosslinkable aqueous polymer composition. The exact type and amount of crosslinking agent or agents used depends upon the specific crosslinkable polymer to be crosslinked, formation temperature conditions, and other factors known to those individuals skilled in the art.

Optionally, the crosslinkable aqueous polymer compositions may further comprise a crosslinking delaying agent, such as a polysaccharide crosslinking delaying agent derived from guar, guar derivatives, or cellulose derivatives. The crosslinking delaying agent may be included in the crosslinkable aqueous polymer compositions, inter alia, to delay crosslinking of the crosslinkable aqueous polymer compositions until desired. One of ordinary skill in the art, with the benefit of this disclosure, will know the appropriate amount of the crosslinking delaying agent to include in the crosslinkable aqueous polymer compositions for a desired application.

4. Consolidation Fluids—Gelable Compositions—Polymerization Organic Monomer Compositions

In other embodiments, the gelled liquid compositions of the present invention comprise polymerizable organic monomer compositions. Generally, suitable polymerizable organic monomer compositions comprise an aqueous-base fluid, a water-soluble polymerizable organic monomer, an oxygen scavenger, and a primary initiator.

The aqueous-based fluid component of the polymerizable organic monomer composition generally may be fresh water, salt water, brine, seawater, or any other aqueous liquid that does not adversely react with the other components used in accordance with this invention or with the subterranean formation.

A variety of monomers are suitable for use as the water-soluble polymerizable organic monomers in the present invention. Examples of suitable monomers include, but are not limited to, acrylic acid, methacrylic acid, acrylamide, methacrylamide, 2-methacrylamido-2-methylpr-opane sulfonic acid, 2-dimethylacrylamide, vinyl sulfonic acid, N,N-dimethylaminoethylmethacrylate, 2-triethylammoniumethylmethacrylate chloride, N,N-dimethyl-aminopropylmethacryl-amide, methacrylamidepropyltriethylammonium chloride, N-vinyl pyrrolidone, vinyl-phosphonic acid, and methacryloyloxyethyl trimethylammonium sulfate, and mixtures thereof. Preferably, the water-soluble polymerizable organic monomer should be self-crosslinking. Examples of suitable monomers which are self crosslinking include, but are not limited to, hydroxyethylacrylate, hydroxymethylacrylate, hydroxyethylmethacrylate, N-hydroxymethylacrylamide, N-hydroxymethyl-methacrylamide, polyethylene glycol acrylate, polyethylene glycol methacrylate, polypropylene gylcol acrylate, polypropylene glycol methacrylate, and mixtures thereof. Of these, hydroxyethylacrylate is preferred. An example of a particularly preferable monomer is hydroxyethylcellulose-vinyl phosphoric acid.

The water-soluble polymerizable organic monomer (or monomers where a mixture thereof is used) should be included in the polymerizable organic monomer composition in an amount sufficient to form the desired gelled substance after placement of the polymerizable organic monomer composition into the subterranean formation. In some embodiments of the present invention, the water-soluble polymerizable organic monomer is included in the polymerizable organic monomer composition in an amount in the range of from about 1% to about 30% by weight of the aqueous-base fluid. In another embodiment of the present invention, the water-soluble polymerizable organic monomer is included in the polymerizable organic monomer composition in an amount in the range of from about 1% to about 20% by weight of the aqueous-base fluid.

The presence of oxygen in the polymerizable organic monomer composition may inhibit the polymerization process of the water-soluble polymerizable organic monomer or monomers. Therefore, an oxygen scavenger, such as stannous chloride, may be included in the polymerizable monomer composition. In order to improve the solubility of stannous chloride so that it may be readily combined with the polymerizable organic monomer composition on the fly, the stannous chloride may be pre-dissolved in a hydrochloric acid solution. For example, the stannous chloride may be dissolved in a 0.1% by weight aqueous hydrochloric acid solution in an amount of about 10% by weight of the resulting solution. The resulting stannous chloride-hydrochloric acid solution may be included in the polymerizable organic monomer composition in an amount in the range of from about 0.1% to about 10% by weight of the polymerizable organic monomer composition. Generally, the stannous chloride may be included in the polymerizable organic monomer composition of the present invention in an amount in the range of from about 0.005% to about 0.1% by weight of the polymerizable organic monomer composition.

The primary initiator is used, inter alia, to initiate polymerization of the water-soluble polymerizable organic monomer(s) used in the present invention. Any compound or compounds that form free radicals in aqueous solution may be used as the primary initiator. The free radicals act, inter alia, to initiate polymerization of the water-soluble polymerizable organic monomer present in the polymerizable organic monomer composition. Compounds suitable for use as the primary initiator include, but are not limited to, alkali metal persulfates; peroxides; oxidation-reduction systems employing reducing agents, such as sulfites in combination with oxidizers; and azo polymerization initiators. Preferred azo polymerization initiators include 2,2′-azobis(2-imidazole-2-hydroxyethyl) propane, 2,2′-azobis(2-aminopropa-ne), 4,4′-azobis(4-cyanovaleric acid), and 2,2′-azobis(2-methyl-N-(2-hydro-xyethyl) propionamide. Generally, the primary initiator should be present in the polymerizable organic monomer composition in an amount sufficient to initiate polymerization of the water-soluble polymerizable organic monomer(s). In certain embodiments of the present invention, the primary initiator is present in the polymerizable organic monomer composition in an amount in the range of from about 0.1% to about 5% by weight of the water-soluble polymerizable organic monomer(s). One skilled in the art will recognize that as the polymerization temperature increases, the required level of activator decreases.

Optionally, the polymerizable organic monomer compositions further may comprise a secondary initiator. A secondary initiator may be used, for example, where the immature aqueous gel is placed into a subterranean formation that is relatively cool as compared to the surface mixing, such as when placed below the mud line in offshore operations. The secondary initiator may be any suitable water-soluble compound or compounds that may react with the primary initiator to provide free radicals at a lower temperature. An example of a suitable secondary initiator is triethanolamine. In some embodiments of the present invention, the secondary initiator is present in the polymerizable organic monomer composition in an amount in the range of from about 0.1% to about 5% by weight of the water-soluble polymerizable organic monomer(s).

Also optionally, the polymerizable organic monomer compositions of the present invention further may comprise a crosslinking agent for crosslinking the polymerizable organic monomer compositions in the desired gelled substance. In some embodiments, the crosslinking agent is a molecule or complex containing a reactive transition metal cation. A most preferred crosslinking agent comprises trivalent chromium cations complexed or bonded to anions, atomic oxygen, or water. Examples of suitable crosslinking agents include, but are not limited to, compounds or complexes containing chromic acetate and/or chromic chloride. Other suitable transition metal cations include chromium VI within a redox system, aluminum III, iron II, iron III, and zirconium IV. Generally, the crosslinking agent may be present in polymerizable organic monomer compositions in an amount in the range of from 0.01% to about 5% by weight of the polymerizable organic monomer composition.

CONCLUSION

The present invention is well adapted to carry out the objects and attain the ends and advantages mentioned above as well as those inherent therein. While preferred embodiments of the invention have been described for the purpose of this disclosure, changes in the construction and arrangement of parts and the performance of steps can be made by those skilled in the art, which changes are encompassed within the spirit of this invention as defined by the appended claims. The inventions are capable of considerable modification, alteration, and equivalents in form and function, as will occur to those ordinarily skilled in the pertinent arts and having the benefit of this disclosure. The depicted and described embodiments of the inventions are exemplary only, and are not exhaustive of the scope of the inventions. Consequently, the inventions are intended to be limited only by the spirit and scope of the appended claims, giving full cognizance to equivalents in all respects.

Claims

1. A method of treating a portion of a subterranean formation penetrated by a wellbore, the method comprising the steps of:

(a) moving a treatment tool through the wellbore on tubing to a desired subterranean location, wherein the treatment tool comprises: (i) a fluidic oscillator; and (ii) a lower packer positioned below the fluidic oscillator;

(b) expanding the cross-section of the lower packer to engage the wellbore, thereby isolating a portion of the wellbore from another portion of the wellbore below the lower packer;

(c) injecting a consolidation fluid through the tubing and through the fluidic oscillator into the isolated portion of the wellbore;

(d) reducing the cross-section of the lower packer, thereby disengaging the tool from the wellbore.

2. The method according to claim 1, wherein the lower packer comprises an a lower inflatable packer.

3. The method according to claim 2, wherein the tool further comprises at least one hydraulic control line to the lower inflatable packer.

4. The method according to claim 3, wherein the step of expanding the cross-section of the lower packer to engage the wellbore further comprises using the hydraulic control line to inflate the lower inflatable packer.

5. The method according to claim 3, wherein the step of reducing the cross-section of the lower packer to disengage the wellbore further comprises using the hydraulic control line to deflate the lower inflatable packer.

6. The method according to claim 1, further comprising the step of injecting a flushing fluid after the step of injecting a consolidation fluid.

7. The method according to claim 1, further comprising repeating the sequence of steps (a) through (d) at least one additional time at a different desired subterranean location.

8. The method of claim 1, wherein the treatment tool is a through-tubing tool for passing through tubing having a smaller cross section area than the cross section area of the wellbore at the treatment location and wherein the lower packer is radially compressible sufficient to pass through the smaller tubing.

9. The method of claim 1, additionally comprising the step of injecting fluids while moving the treatment tool through a portion of the wellbore.

10. The method of claim 1, wherein the moving step comprises passing the injection apparatus through a restriction in the well having a cross section area less than the cross section area of the lower packer when in the expanded condition.

11. A method of treating a portion of a subterranean formation penetrated by a wellbore, the method comprising the steps of:

(a) moving a treatment tool through the wellbore on tubing to a desired subterranean location, wherein the treatment tool comprises: (i) a fluidic oscillator; (ii) an upper packer positioned above the fluidic oscillator; and (iii) a lower packer positioned below the fluidic oscillator;

(b) expanding the cross-section of each of the upper packer and the lower packer to engage the wellbore, thereby isolating a portion of the wellbore between the upper packer and the lower packer;

(c) injecting a consolidation fluid through the tubing and through the fluidic oscillator into the isolated portion of the wellbore;

(d) reducing the cross-section of the upper packer and the lower packer, thereby disengaging the tool from the wellbore.

12. The method according to claim 11, wherein the upper packer and the lower packer each comprise an upper inflatable packer and a lower inflatable packer, respectively.

13. The method according to claim 12, wherein the tool further comprises at least one hydraulic control line to the upper inflatable packer and to the lower inflatable packer.

14. The method according to claim 13, wherein the step of expanding the cross-section of each of the upper packer and the lower packer to engage the wellbore further comprises using the hydraulic control line to inflate each of the upper inflatable packer and the lower inflatable packer.

15. The method according to claim 13, wherein the step of reducing the cross-section of each of the upper packer and the lower packer to disengage the wellbore further comprises using the hydraulic control line to deflate each of the upper inflatable packer and the lower inflatable packer.

16. The method according to claim 11, further comprising the step of injecting a flushing fluid after the step of injecting a consolidation fluid.

17. The method according to claim 11, further comprising repeating the sequence of steps (a) through (d) at least one additional time at a different desired subterranean location.

18. The method of claim 11, wherein the treatment tool is a through-tubing tool for passing through tubing having a smaller cross section area than the cross section area of the wellbore at the treatment location and wherein the upper and lower packers are radially compressible sufficient to pass through the smaller tubing.

19. The method of claim 11, additionally comprising the step of injecting fluids while moving the treatment tool through a portion of the wellbore.

20. The method of claim 1, wherein the moving step comprises passing the injection apparatus through a restriction in the well having a cross section area less than the cross section area of the upper packer and of the lower packer when in the expanded condition.